The present invention relates to methods to enhance the productivity of hydrocarbon producing wells (e.g., oil wells) by creating alternate flow paths by removing portions of a wellbore coating, dissolving small portions of the formation, or removing (by dissolution) near-wellbore formation damage. Generally speaking, acids or acid-based fluids are useful for this purpose due to their ability to dissolve both formation minerals and contaminants (e.g., drilling fluid components coating the wellbore or that have penetrated the formation) which were introduced into the wellbore/formation during drilling or remedial operations. In the case of treatments within the formation (rather than wellbore treatments) the portion of the formation that is near the wellbore and that first contacts the acid is adequately treated, though portions of the formation more distal to the wellbore (as one moves radially outward from the wellbore) may remain untouched by the acid, because all of the acid reacts before it can get very far from the wellbore.
For instance, sandstone formations are often treated with a mixture of hydrofluoric and hydrochloric acids (called mud acid), usually at very low injection rates (to avoid fracturing the formation). This acid mixture is often selected because it will dissolve clays (found in drilling mud) as well as the primary constituents of naturally occurring sandstones (e.g., silica, feldspar, and calcareous material). In fact, the dissolution is so rapid that the injected mud acid is essentially spent by the time it reaches a few inches beyond the wellbore. Thus, it can be calculated that, because of reaction, a far greater amount of acid would be required to achieve radial penetration of even a single foot, if a conventional mud acid fluid were used to treat a damaged sandstone at high temperatures, than would be required to fill the pores of a region extending to five feet from the wellbore (assuming 20 percent formation porosity and a 6-inch wellbore diameter). Recent studies on matrix stimulation (treatment below fracture pressure) have strongly emphasized the importance of secondary and tertiary reactions in determining the success of matrix stimulation treatments. These reactions produce solids, such as hydrated silica or gibbsite (Al(OH)3), which can damage the formation during the stimulation process. Sandstone formations frequently contain clays and other minerals made up of aluminosilicates. Fluids containing chelating agents as well as HF-producing chemicals have been proposed for treatment of sandstone formations.
Chelating agents are materials that are employed, among other uses, to control undesirable reactions of metal ions. In oilfield chemical treatments, chelating agents are frequently added to matrix stimulation acids to prevent precipitation of solids (metal control) as the acids spend on the formation being treated. (See Frenier W. W., et al., “Use of Highly Acid-Soluble Chelating Agents in Well Stimulation Services,” SPE 63242 (2000).) These precipitates include iron hydroxide and iron sulfide. In addition, chelating agents are used as components in many scale removal/prevention formulations. (See Frenier, W. W., “Novel Scale Removers Are Developed for Dissolving Alkaline Earth Deposits,” SPE 65027 (2001).) Two different types of chelating agents are in use: polycarboxylic acids (including aminocarboxylic acids and polyaminopolycarboxylic acids) and phosphonates. Chelating formulations based on ethylenediaminetetraacetic acid (EDTA) have been used extensively to control iron precipitation and to remove scale. Formulations based on nitrilotriacetic acid (NTA) and diethylenetriaminepentaacetic acid (DTPA) also are in use. Hydroxy chelating agents have also been proposed for use in matrix stimulation of carbonates (see Frenier, et al., “Hydroxyaminocarboxylic Acids Produce Superior Formulations for Matrix Stimulation of Carbonates,” SPE 68924 (2001)) as well as for use as metal control agents and in scale removal fluids. The materials evaluated include hydroxy-aminopolycarboxylic acids (HACA) such as hydroxyethylethylenediaminetriacetic acid (HEDTA) as well as other types of chelating agents.
Fredd and Fogler (see Fredd, C. N., and H. S. Fogler, “The Influence of Transport and Reaction on Wormhole Formation in Porous Media,” J. Am. Inst. Chem. Eng., 44, 1933-1949 (1998); Fredd, C. N., and H. S. Fogler, “The Influence of Chelating Agents on the Kinetics of Calcite Dissolution,” J. Col. Interface. Sci., 204, 187-197 (1998); and Fredd, C. N. and Fogler, H. S., “The Kinetics of Calcite Dissolution in Acetic acid Solutions,” Chem. Eng. Sci., 22, 3863-3874 (1998)) have proposed a use for EDTA-type chelating agents that employs the chelating agents as the primary dissolution agent in matrix acidizing of carbonate formations (in particular calcite: calcium carbonate; and dolomite: calcium/magnesium carbonate). The purpose of the carbonate matrix acidizing treatment is to remove near wellbore damage and to produce “wormholes” that increase the permeability of the near wellbore region. Because HCl reacts so rapidly with most carbonate surfaces, diverting agents, ball sealers and foams are typically used to direct some of the acid flow away from large channels that may form initially and take all of the subsequent acid volume. By adjusting the flow rate and pH of the fluid, it becomes possible to tailor the slower reacting EDTA solutions to the well conditions and achieve maximum wormhole formation with a minimum amount of solvent. However, acids and methods used for carbonate stimulation are not the same as those used for sandstone stimulation.
Disodium EDTA has been used as a scale-removal agent in the Prudhoe Bay field of Alaska (see Shaughnessy, C. M. and W. E. Kline, “EDTA Removes Formation Damage at Prudhoe Bay,” SPE Paper 11188 (1982)). In this case, CaCO3 scale had precipitated in the perforation tunnels and in the near-wellbore region of a sandstone formation. High decline rates followed conventional HCl treatments, but 17 wells treated with disodium EDTA maintained production after these treatments. Rhudy (see Rhudy, J. S., “Removal of Mineral Scale From Reservoir Core by Scale Dissolver,” SPE Paper 25161 (1993)) reviewed the use of EDTA and DTPA formulations to remove Ca, Ba and Sr scales from reservoir cores. However, many fluid properties and procedures required for successful scale removal are different from those required for successful sandstone stimulation.
Huang (see Huang, T., et al. “Acid Removal of Scale and Fines at High Temperatures,” SPE paper 74678 (2002)) described the acid removal of scale and fines at high temperatures. This fluid (believed to be a mixture of organic acids) was developed to clean fines-plugged screens and/or gravel packs, especially in high-temperature formations. Due to the type of metallurgy, long acid contact times, and high acid sensitivity of the formations, removal of the scale with HCl acids had been largely unsuccessful. A series of tests conducted on screens and clayrich cores showed that a new organic acid system, which was highly biodegradable, could successfully remove the calcium carbonate scale and fines to stimulate production. They reported that core flood testing demonstrated that this organic acid system could effectively remove calcium carbonate scales and fines at temperatures up to 204° C. (400° F.). Corrosion tests showed that at 177° C. (350° F.), the corrosion rate caused by this organic acid was 0.00049 g/cm2 (0.001 lb/ft2) on 22-Cr for 16 hours. (Also see Ali, A., et al. “Chelating Agent-Based Fluids for Optimal Stimulation of High-Temperature Wells,” SPE paper 63242 (2002).) This paper also discusses use of chelating agent formulations for stimulation of sandstones and carbonates at high temperatures.
U.S. Pat. No. 6,436,880 (assigned to Schlumberger Technology Corporation) describes a well treatment fluid composition containing a first acid, in an amount of from about 0.1 weight percent to about 28 weight percent, preferably selected from HCl, HF, formic acid, acetic acid, or mixtures of those acids, and a second acid, in an amount from about 0.5 to about 30 weight percent, that is HEIDA (hydroxyethyliminodiacetic acid) or one of its salts, and/or HEDTA (hydroxyethylethylenediaminetetraacetic acid) or one of its salts. This patent also describes methods of matrix acidizing, and removal of scale and/or drilling mud from wellbores using this fluid composition. U.S. Patent Application Publication No. 2002/0170715 (assigned to Schlumberger Technology Corporation) describes matrix stimulation with a composition containing potassium, lithium or ammonium salts of EDTA (ethylenediaminetetraacetic acid) or DTPA (diethylenetriaminepentaacetic acid). U.S. Patent Application Publication Nos. 2002/0104657 and 2002/0070022 (assigned to Schlumberger Technology Corporation) describe an acidic composition containing fluoboric acid and an acid, or mixture of acids, which chelate aluminum ions and aluminum fluoride species. The fluoboric acid may be made from a fluoride source (such as HF or an HF source such as ammonium fluoride or ammonium bifluoride, optionally plus HCl) and a borate source, such as boric acid. The chelating acids may be polycarboxylic acids (such as citric, tartaric or malic acids) or aminocarboxylic acids such as nitrilotriacetic acid (NTA), HEDTA, HEIDA, or their ammonium or potassium salts. These applications also describe methods of using these acidic compositions for matrix stimulation.
U.S. Pat. No. 4,090,563 describes an “aqueous mud acid solution” containing a weak acid (preferably citric, formic, or acetic acid), a weak acid salt (preferably the ammonium salt of the weak acid), a fluoride salt (preferably ammonium fluoride), and a partial salt of an aminopolyacetic acid chelating agent (preferably EDTA having 2.5 ammonium ions). The partial salt of the aminopolyacetic acid chelating agent can serve as the weak acid salt. The solution was found to be effective for dissolving siliceous materials such as bentonite clay. However, one of the inventors later described adding EDTA having 2.5 ammonium ions to an acetic acid/ammonium hydroxide buffered HF sandstone acidizing fluid to improve the ability of the fluid to hold aluminum and magnesium ions in solution and therefore reduce the amount of reaction-product precipitates, but he reported that not only did this not work relative to the fluid without the chelant, but it resulted in more precipitation of silica as well (R. F. Scheuerman, SPE paper 13563; SPE Production Engineering, pp. 15-21, February (1988)).
U.S. Pat. No. 6,531,427 describes a method of acidizing an aluminum containing sandstone using as an acidizing composition a fluid containing water, HF and at least one hydroxy carboxylic acid (preferably citric, tartaric, malic, lactic or hydroxyacetic acid) present in an amount of from 2.1 weight percent to about 10 weight percent. The method is said to be effective for the prevention of precipitation of aluminum fluoride compounds.
Sandstone matrix “stimulation” is often ineffective and sometimes damaging. The precipitation of silica is thought to be the major reason that sandstone-acidizing jobs fail to produce the anticipated decrease in skin, especially at temperatures >150° F. (66° C.) or in the presence of acid sensitive clay. There is a need for fluids and methods to increase the stimulation ratio (reduce overall skin) by eliminating some of the precipitation reactions. There is a need for fluids and methods that will not damage sandstone formations.